In the oil and gas industry and in the petrochemical industry, fluids are commonly transported and processed in metal pipes and conduits, typically made of steel. These pipes and conduits carry fluids containing amounts of oil and/or water and are also likely to contain hydrocarbon or other gases and solids. The solids can arise from the rock formation or due to the presence of in situ chemical deposits (e.g. scale, wax) or corrosion by-products or due to precipitation of previously dissolved species due to a change in the physical or chemical environment. A typical length of pipe used in the oil industry is likely to contain all of these compounds in various amounts over its lifetime.
Water produced in the extraction of oil is typically acidic, especially in the presence of carbon dioxide and/or hydrogen sulphide which are often present during the extraction process. Bacteria found in industrial environments, particularly sulphate-reducing bacteria, can initiate or accelerate the corrosion in these systems. In addition, stimulation of wells may involve the injection of chemical products. For example, acid-based liquids may be introduced in the well during drilling or recovery operations. These acidic compounds can be extremely corrosive and corrosion inhibitors may be added to the fluids that come into contact with metallic surfaces. These corrosion inhibitors can either form a film protecting the metallic surface or reduce the corrosion process by means of physical and/or chemical reactions on metallic surfaces.
Organic corrosion inhibitors are the most commonly used corrosion inhibitors in use in oilfield systems and are also commonly used in oil and gas processing and petrochemical industries. The active ingredient is usually a detergent-like or surfactant molecule with a charged polar (i.e. water-soluble or hydrophilic) head group and an uncharged non-polar (i.e. oil-soluble or lipophilic) tail. When introduced into a pipe, these compounds rapidly partition to regions of polarity interfaces where the opposite electrostatic properties of each part of the molecule create least energetic repulsions. In practice, the molecules rapidly absorb to the surface of the pipe, which is highly charged, and form ordered two-dimensional structures on the surface thereby creating a protective film.
Surfaces requiring protection include pipes, conduits, tubes, and other metal fixtures and any component in regular contact with corrosive fluids. These pipes may be used in exploration, drilling, completion, production operations, refining, and/or transportation of produced fluids, products or intermediates. Corrosion inhibitors are also used in fields other than that of oil production, for example in water treatment systems, refineries, petrochemical, paper manufacturing and inhibitors may even be added to diesel to prevent corrosion from wet fuel.
Corrosion is a growing problem particularly for older oil wells, since the composition of produced fluids changes from predominantly hydrocarbons to hydrocarbon/brine mixtures to predominantly brine with lower hydrocarbon yields. The increasing value of petroleum products and the decreasing availability of new and easily extractable sources mean that the average age of producing wells is increasing and so the capacity for corrosion increases too. On average, it is estimated that three barrels of water are produced for every barrel of oil produced globally. Gas wells also suffer from increasing corrosion with age due to the increased exposure to corrosive environments. Deliberate transport of potentially corrosive fluids, such as carbon dioxide for carbon sequestration, and extraction of petroleum sources such as acid crude and highly sour gas condensates, is also becoming more common and is likely to increase further in the future.
Maintaining the amount of corrosion inhibitors at about an effective concentration is critical to maximising steel protection and minimising over use of chemicals. Inhibitor residuals provide close control of a system. The basis of any residual monitoring is that active corrosion inhibitors may be consumed in the inhibition process or lost due to deposit, corrosion and chemical degradation processes and combinations of such phenomena. The inhibitor may also be lost with the produced fluids for example when it is injected down a well and is then brought up within the oil and water. In this case, the inhibitor is then either disposed of with the water or passed through to the oil processing facilities.
Many methods for controlling the corrosion inhibitor concentration are based on knowing how much has been used and converting the amount into availability. Some techniques are also available to detect coverage of a steel surface with chemical.
Corrosion inhibitor formulations are complex chemical mixtures and difficult to monitor because of the large number of components involved. Few monitoring methods measure all components of a formulation. For example, a colourimetric approach may be used which is based on the detection of colour produced with the reaction of compounds with amines. However, this approach is limited to the monitoring of specific classes of chemicals. Alternatively, in the ion pair technique, an excess of a large anionic molecule is added to the water containing a cationic corrosion inhibitor. The ion pair formed is then extracted into a solvent and its concentration determined colourimetrically. A disadvantage of the ion pair technique is that the method is restricted to formulations with known chemical composition and needs to be tailored to the components of the composition. Another disadvantage is that the limit of detection of the ion pair technique is generally only about 5 ppm for inhibitor residuals.
Ultraviolet (UV) absorption methods that are based upon the measurement of the absorbance of UV light by a component of a corrosion inhibitor formulation may also be used. Fluorescence methods are also available, which methods use the fluorescence spectra or emission intensities of specific inhibitors. These methods are prone to error from other absorbent or fluorescent species.
Other techniques provide more information about the concentration of particular components in a fluid sample, such as ESI MS-MS (electro-spray ionisation tandem mass spectrometry). However, this method is time-consuming, uses expensive and bulky equipment that is not suitable for offshore manipulation, and requires regular maintenance. ESI MS-MS systems must be handled by skilled technicians and do not normally provide quantitative information. Less sophisticated mass spectrometry variations can be used but they are less informative and are still complicated and laboratory based. In addition, mass spectrometry usually requires the chemical composition of the formulation to be known and the method must be modified and tailored to the components of the composition. However, chemical companies rarely release information on the exact components of their corrosion inhibitor formulation and service companies often bind operators to “non-analysis agreements” to specifically stop them from analysing their formulations for chemical composition. Interpretation of results can therefore be difficult.
Functional tests are available that monitor the severity of corrosion in a system rather than the amount of chemical used or left. For example, methods using linear polarization resistance, electrical resistance or weight loss may be used. However, these methods are specific to a particular location rather than the full conduit.
Corrosion coupons are also widely used and provide quantitative results at reasonable cost. Coupons of predetermined shape, size, surface area and with similar metallurgical properties to that of process equipment are inserted into the process stream and re-weighed and visually analysed after a set exposure period. Removal from the system and lab analysis is required to provide corrosion rate and measurements such as pitting and scaling. The information from the coupon is an additive effect of typically three months and so the temporal resolution of this monitoring system is very low. Further, although information on the corrosive capacity of a system is available, no direct information on levels of corrosion inhibitor residuals is provided. The coupon method provides evidence that corrosion has occurred and so only reactive corrective measures are possible.
Many of the techniques described above can only be used in aqueous systems and are unsuitable for fluids comprising larger amounts of oil. The specific abilities will be slightly different for each different technology. False increase or decrease in signal from interferences means levels have significant uncertainty. All the techniques are susceptible to interferences and oil components often need to be extracted from the water sample to be analysed. The extraction process can be time consuming and technically difficult. In addition, inhibitor may be lost during the extraction process.
There is therefore a need for a method for monitoring the concentration of corrosion inhibitor in a fluid. Most importantly, there is a need for a method that provides information on whether effective corrosion residual concentrations are present in the fluid. The method needs to be simple, rapid and applicable without the need for expensive equipment. The need for extractions must be minimised and the method should be performable offshore, for example, on an oil rig or other oil extraction or production site. The method needs to be independent of the particular chemical formulation of the corrosion inhibitor so that it can be widely applicable.